1. Field of the Invention
Embodiments of the present invention generally relate to the field of subsea production operations. Embodiments of the present invention further pertain to methods for managing hydrate formation in subsea equipment such as a production line.
2. Background of the Invention
More than two-thirds of the Earth's surface is covered by oceans. As the petroleum industry continues its search for hydrocarbons, it is finding that more and more of the untapped hydrocarbon reservoirs are located beneath the oceans. Such reservoirs are referred to as “offshore” reservoirs.
A typical system used to produce hydrocarbons from offshore reservoirs includes hydrocarbon-producing wells located on the ocean floor. The producing wells are sometimes referred to as “producers” or “subsea production wells.” The produced hydrocarbons are transported from the producing wells to a host production facility which is located on the surface of the ocean or immediately on-shore.
The producing wells are in fluid communication with the host production facility via a system of pipes that transport the hydrocarbons from the subsea wells on the ocean floor to the host production facility. This system of pipes typically comprises a collection of jumpers, flowlines and risers. Jumpers are typically referred to in the industry as the portion of pipes that lie on the floor of the body of water. They connect the individual wellheads to a central manifold, or directly to a production flowline. The flowline also lies on the marine floor, and transports production fluids from the manifold to a riser. The riser refers to the portion of a production line that extends from the seabed, through the water column, and to the host production facility. In many instances, the top of the riser is supported by a floating buoy, which then connects to a flexible hose for delivering production fluids from the riser to the production facility.
The drilling and maintenance of remote offshore wells is expensive. In an effort to reduce drilling and maintenance expenses, remote offshore wells are oftentimes drilled in clusters. A grouping of wells in a clustered subsea arrangement is sometimes referred to as a “subsea well-site.” A subsea well-site typically includes producing wells completed for production at one and oftentimes more “pay zones.” In addition, a well-site will oftentimes include one or more injection wells to aid in maintaining in-situ pressure for water drive and gas expansion drive reservoirs.
The grouping of remote subsea wells facilitates the gathering of production fluids into a local production manifold. Fluids from the clustered wells are delivered to the manifold through the jumpers. From the manifold, production fluids may be delivered together to the host production facility through the flowline and then the riser. For well-sites that are in deeper waters, the gathering facility is typically a floating production storage and offloading vessel, or “FPSO.” The FPSO serves as a gathering and processing facility.
One challenge facing offshore production operations is flow assurance. During production, the produced fluids will typically comprise a mixture of crude oil, water, light hydrocarbon gases (such as methane), and other gases such as hydrogen sulfide and carbon dioxide. In some instances, solid materials such as sand may be mixed with the fluids. The solid materials entrained in the produced fluids may typically be deposited during “shut-ins,” i.e. production stoppages, and require removal.
Of equal concern, changes in temperature, pressure and/or chemical composition along the pipes may cause the deposition of other materials such as methane hydrates, waxes or scales on the internal surface of the flowlines, valves and risers. These deposits need to be periodically removed, as build-up of these materials can reduce internal line size and constrict flow.
Hydrates are crystals formed by water in contact with natural gases and associated liquids, in a ratio of 85 mole % water to 15% hydrocarbons. Hydrates can form when hydrocarbons and water are present at the right temperature and pressure in wells, flow lines, and valves. The hydrocarbons become encased in crystalline structures which can rapidly grow and agglomerate to sizes which can block flow. Hydrate formation most typically occurs in subsea production lines which are at relatively low temperatures and elevated pressures.
The low temperatures and high pressures of a deepwater environment cause hydrate formation as a function of gas-to-water composition. In a subsea pipeline, hydrate masses usually form at the hydrocarbon-water interface, and may accumulate as flow pushes them downstream. The resulting porous hydrate plugs have the unusual ability to transmit some degree of gas pressure, while acting as a flow hindrance to liquid. Both gas and liquid may sometimes be transmitted through the plug; however, lower viscosity and surface tension favors the flow of gas.
It is desirable to maintain flow assurance between cleanings by minimizing hydrate formation. One offshore method used for hydrate plug removal is the depressurization of the pipeline system. Traditionally, depressurization is most effective in the presence of lower water cuts. However, the depressurization process sometimes prevents normal production for several weeks. At higher water cuts, gas lift procedures may be required. Further, hydrates may quickly re-form when the well is placed back on line.
Most known deepwater subsea pipeline arrangements rely on two production lines for hydrate management. In the event of an unplanned shutdown, production fluids in the flowline and riser are commonly displaced with dehydrated dead crude oil using a pig. Displacement is completed before the production fluids (which are typically untreated or “uninhibited”) cool down below the hydrate formation temperature. This prevents the creation of a hydrate blockage in the production lines. The pig is launched into one production line, is driven with the dehydrated dead crude out to the production manifold, and is driven back to the host facility through the second production line.
The two-production-line operation is feasible for large installations. However, for relatively small developments the cost of a second production line can be prohibitive. Therefore, an improved process of hydrate management is needed which does not, in certain embodiments, employ or rely upon two production lines. Further, a need exists for a hydrate management method that utilizes a water injection line and a single production line.